MIDLAND, Texas--(BUSINESS WIRE)--Concho Resources Inc. (NYSE: CXO) (“Concho” or the “Company”) today
reported financial and operating results for the three months and year
ended December 31, 2013. Highlights for the year ended December 31, 2013
include:

Production of 33.6 million barrels of oil equivalent (“MMBoe”) for
2013, a 20% increase over 2012 production from continuing operations

Net income of $251.0 million, or $2.39 per diluted share, for 2013, as
compared to net income of $431.7 million, or $4.15 per diluted share,
in 2012

Adjusted net income1 (non-GAAP) of $368.7 million, or $3.51
per diluted share, for 2013, as compared to $388.9 million, or $3.74
per diluted share, for 2012

EBITDAX2 (non-GAAP) of $1,685.6 million for 2013, a 14%
increase over 2012

1 Adjusted net income (non-GAAP) is comparable to securities
analyst estimates. For an explanation of how we calculate adjusted net
income (non-GAAP) and a reconciliation of net income (GAAP) to adjusted
net income (non-GAAP), please see "Supplemental Non-GAAP Financial
Measures" below.

2 For an explanation of how we calculate and use EBITDAX
(non-GAAP) and a reconciliation of net income (GAAP) to EBITDAX
(non-GAAP), please see "Supplemental Non-GAAP Financial Measures" below.

Financial Results

Production for 2013 totaled 33.6 MMBoe (21.1 million barrels of oil
(“MMBbls”) and 75.1 billion cubic feet of natural gas (“Bcf”)), an
increase of 20% as compared to 28.0 MMBoe (16.9 MMBbls of crude oil and
66.6 Bcf of natural gas) produced in 2012 from continuing operations.

In the fourth quarter of 2013 production was 8.9 MMBoe (5.8 MMBbls of
crude oil and 19.0 Bcf of natural gas), or 97.0 thousand barrels of oil
equivalent (“MBoe”) per day, a 14% increase over the comparable
prior-year period of 7.8 MMBoe (4.7 MMBbls of crude oil and 18.5 Bcf of
natural gas). Sequentially, Concho’s total fourth quarter 2013
production increased 3% as compared to the previous quarter of 8.7 MBoe
(5.4 MMBbls of crude oil and 19.6 Bcf of natural gas) and crude oil
production during the fourth quarter increased 7% over the previous
quarter, despite the winter weather-related curtailments. The fourth
quarter of 2013 was Concho’s 16th consecutive quarter to increase crude
oil production from continuing operations over the immediately previous
quarter.

“We are in a unique position of hitting our execution stride just as we
are beginning to define the true depth and scale of the resource
potential that exists across our assets,” commented Tim Leach, Chairman,
Chief Executive Officer and President. “Concho delivered substantial
crude oil growth during 2013 while building the largest horizontal
development program in the Permian Basin. As we enter the first year of
our acceleration plan to double production by year-end 2016, we have
significant momentum and opportunity to continue our track record of
solid execution and growth.”

For 2013, the Company reported net income of $251.0 million, or $2.39
per diluted share, as compared to net income of $431.7 million, or $4.15
per diluted share, for 2012. The Company’s 2013 results were impacted by
several non-cash and unusual items including: (1) a $123.7 million loss
on derivatives not designated as hedges, (2) $32.3 million in cash
payments on commodity derivatives, (3) $65.4 million of impairments of
long-lived assets, (4) $49.8 million of leasehold abandonments, (5) a
$28.6 million loss on extinguishment of debt, (6) a $1.3 million loss on
disposition of assets, net, (7) $11.4 million of other settlements, (8)
a $19.6 million gain related to the disposition of non-core assets
included in discontinued operations and (9) a $21.9 million benefit for
a change in state statutory effective income tax rate. Excluding these
items and their tax effects, the 2013 adjusted net income (non-GAAP) was
$368.7 million, or $3.51 per diluted share. Excluding similar non-cash
items and their tax impact, adjusted net income (non-GAAP) for 2012 was
$388.9 million, or $3.74 per diluted share. For a description and a
reconciliation of net income (GAAP) to adjusted net income (non-GAAP),
please see “Supplemental Non-GAAP Financial Measures” below.

EBITDAX was $1,685.6 million in 2013, an increase of 14% from $1,475.6
million in 2012. For a description and a reconciliation of net income
(GAAP) to EBITDAX (non-GAAP), please see “Supplemental Non-GAAP
Financial Measures” below.

Oil and natural gas sales from continuing operations for 2013 increased
27% when compared to 2012. This increase was attributable to a 20%
increase in production from continuing operations in 2013 compared to
2012 and a 4% increase in the Company’s unhedged realized oil price in
2013 compared to 2012.

Oil and natural gas production expense from continuing operations for
2013, including oil and natural gas taxes, totaled $455.4 million, or
$13.54 per barrel of oil equivalent (“Boe”), a 10% increase per Boe from
2012. This increase was due primarily to higher lease operating
expenses (“LOE”) and workover costs, which averaged $7.85 per Boe in
2013 as compared to $6.90 per Boe in 2012. The increase in LOE and
workover costs per Boe during 2013 was primarily due to increased
activity in higher-cost areas with developing infrastructure, like the
Delaware Basin.

Depreciation, depletion and amortization expense (“DD&A”) from
continuing operations for 2013 totaled $772.6 million, or $22.97 per
Boe, a 12% increase per Boe from 2012.

General and administrative expense (“G&A”) from continuing operations
for 2013 totaled $169.8 million, or $5.04 per Boe, as compared to $133.8
million, or $4.79 per Boe, in 2012. Cash G&A expenses for 2013 totaled
$134.7 million and stock-based compensation (non-cash) totaled $35.1
million. The increase in per Boe expense for 2013 over 2012 was
primarily due to a 27% increase in absolute G&A expenses reflecting
increased staffing across the Company, and was partially offset by a 20%
increase in production from continuing operations.

The Company’s cash flow from operating activities (GAAP) was $1,362.0
million for 2013, as compared to $1,237.5 million for 2012, an increase
of 10%. Adjusted cash flows (non-GAAP), which are cash flows from
operating activities (GAAP) adjusted for settlements on derivatives not
designated as hedges, were $1,329.7 million for 2013, as compared to
$1,261.0 million for 2012, an increase of 5%. For a description of
the use of adjusted cash flows (non-GAAP) and for a reconciliation of
cash flows from operating activities (GAAP) to adjusted cash flows
(non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Operations

For 2013, the Company commenced drilling or participated in a total of
633 gross wells (465 operated, 44% horizontal), 4 of which were
unsuccessful, and completed 675 wells as producers.

The table below summarizes the Company’s gross drilling activities by
core area for the fourth quarter and full year 2013:

Total Wells

Operated Wells

Completed Wells1

4Q 2013

FY 2013

4Q 2013

FY 2013

4Q 2013

FY 2013

New Mexico Shelf

26

197

6

83

34

223

Delaware Basin

63

202

49

149

50

192

Texas Permian

34

234

33

233

38

260

Total

123

633

88

465

122

675

1 Excludes 4 wells that were unsuccessful in 2013.

Currently, the Company is operating 34 drilling rigs; 2 of these rigs
are drilling Yeso wells in the New Mexico Shelf, 11 are drilling in the
Texas Permian and 21 are drilling in the Delaware Basin. Of the 34
operated rigs, the Company is currently running 30 horizontal drilling
rigs, including 21 in the Delaware Basin, 7 in the Texas Permian and 2
in the New Mexico Shelf.

Year-End 2013 Location Update

At year-end 2013, the Company had identified approximately 22,000
drilling locations across its 1.2 million gross (605,000 net) acreage
position. The resource potential associated with these 22,000 drilling
locations including what the Company has identified as proved is
approximately six times the Company's year-end 2013 proved reserves of
503 MMBoe.

New Mexico Shelf

At year-end 2013, the Company had identified approximately 2,700
drilling locations in the New Mexico Shelf. Of these 2,700 drilling
locations, approximately 1,100 locations target the Yeso formation
vertically and approximately 1,250 locations target the Yeso formation
horizontally.

As previously disclosed, the New Mexico Shelf experienced natural gas
processing issues during 2013, which the Company estimates to have
reduced full-year volumes by over 500 MBoe. Recently, the Company has
seen continued improvement in line pressures and is monitoring multiple
projects designed to further improve processing and takeaway capacity
that are currently being developed and expected to be operational by
mid-2014.

Delaware Basin

At year-end 2013, the Company had identified approximately 10,600
drilling locations in the Delaware Basin. In the northern Delaware
Basin, these locations include approximately 6,000 locations targeting
the Bone Spring sands, approximately 1,500 targeting the Avalon shale,
approximately 1,400 targeting the Wolfcamp, and approximately 850
targeting the Brushy Canyon. In the southern Delaware Basin, these
locations include approximately 800 Wolfcamp and 2nd Bone
Spring sands locations.

Of the 63 wells drilled in the Delaware Basin in the fourth quarter of
2013, 45 were Bone Spring sands wells, 12 were Wolfcamp shale wells, 5
were Brushy Canyon wells, and 1 was an Avalon shale well. The Company’s
net production in the fourth quarter of 2013 from horizontal Delaware
Basin wells averaged approximately 35.9 MBoe per day, an increase of 70%
over the fourth quarter of 2012 and an increase of 7% over the third
quarter of 2013.

In the northern Delaware Basin, 26 new wells had at least 30 days of
production by the end of the fourth quarter of 2013, with an average
30-day rate of 749 barrels of oil equivalent per day (“Boepd”) (77% oil)
and an average 24-hour peak rate of 1,121 Boepd from an average lateral
length of 4,327 feet.

In the southern Delaware Basin, 21 wells had at least 30 days of
production by the end of the fourth quarter of 2013, with an average
30-day rate of 984 Boepd (80% oil) and an average 24-hour peak rate of
1,303 Boepd from an average lateral length of 4,378 feet.

Texas Permian

At year-end 2013, the Company had identified approximately 8,500
drilling locations. Of these 8,500 drilling locations, approximately
1,800 target the vertical Wolfberry play on 40-acre spacing,
approximately 2,500 target the vertical Wolfberry play on 20-acre
spacing, approximately 1,400 target the vertical shallow Wolfcamp and
approximately 2,500 target the horizontal Spraberry and Wolfcamp.

In the Texas Permian, 12 horizontal wells had at least 30 days of
production by the end of the fourth quarter of 2013, with an average
30-day rate of 614 Boepd (75% oil) and an average 24-hour peak rate of
915 Boepd (78% oil) from an average lateral length of 4,415 feet.

Derivative Update

The Company maintains an active crude oil and natural gas hedging
program and has continued to add to its derivative positions. Please
see the “Derivatives Information” table at the end of this press release
for more detailed information about the Company’s current derivative
positions.

Credit Facility

At December 31, 2013, the Company had borrowings outstanding under its
credit facility of $250.0 million, and the availability under the credit
facility was approximately $2.2 billion.

Guidance

The Company’s 2014 production guidance range is 18 - 22% growth over
2013 volumes. For the first quarter of 2014, the Company expects
production to average between 98 - 101 MBoe per day. Additionally, the
Company is forecasting first quarter of 2014 LOE to be above the full
year guidance range of $7.50 - $8.00 per Boe due, in part, to increased
costs associated with restoring production from the winter weather in
the fourth quarter of 2013. However, the Company expects full year 2014
lease operating expense to fall within the original guidance range of
$7.50 - $8.00 per Boe.

Conference Call and Presentation Information

The Company will host a conference call with an accompanying
presentation on Thursday, February 20, 2014, at 9:00 a.m. CST to further
discuss information regarding 2013 reserves, inventory and fourth
quarter and full-year 2013 financial and operating results. Interested
parties may listen to the conference call via the Company’s website at www.concho.com
or by dialing (877) 415-3186 (passcode: 28809385). The presentation is
also available on the Company’s website. To access the presentation,
visit www.concho.com
and select “Investor Relations,” then “Presentations.”

A replay of the conference call will be available on the Company’s
website or by dialing (888) 286-8010 (passcode: 17690036).

About Concho Resources Inc.

Concho Resources Inc. is an independent oil and natural gas company
engaged in the acquisition, development and exploration of oil and
natural gas properties. The Company's operations are focused in the
Permian Basin of Southeast New Mexico and West Texas. For more
information, visit Concho’s website at www.concho.com.

Forward-Looking Statements and Cautionary Statements

The foregoing contains forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements, other than statements
of historical facts, included in this press release that address
activities, events or developments that the Company expects, believes or
anticipates will or may occur in the future are forward-looking
statements. Without limiting the generality of the foregoing,
forward-looking statements contained in this press release specifically
include statements, estimates and projections regarding the Company's
future financial position, operations, performance, production growth,
returns, divestitures, capital expenditure budget, the proceeds of the
sale of the non-core properties, oil and natural gas reserves, number of
identified drilling locations, drilling program, derivative activities,
costs and other guidance. These statements are based on certain
assumptions made by the Company based on management's experience,
expectations and perception of historical trends, current conditions,
anticipated future developments and other factors believed to be
appropriate. Forward-looking statements are not guarantees of
performance. Although the Company believes the expectations reflected in
its forward-looking statements are reasonable and are based on
reasonable assumptions, no assurance can be given that these assumptions
are accurate or that any of these expectations will be achieved (in full
or at all) or will prove to have been correct. Moreover, such statements
are subject to a number of assumptions, risks and uncertainties, many of
which are beyond the control of the Company, which may cause actual
results to differ materially from those implied or expressed by the
forward-looking statements. These include the factors discussed or
referenced in the "Risk Factors" section of the Company's most recent
Form 10-K and 10-Q filings and risks relating to declines in the prices
we receive for our oil and natural gas; uncertainties about the
estimated quantities of reserves; risks related to the integration of
acquired assets; the effects of government regulation, permitting and
other legal requirements, including new legislation or regulation of
hydraulic fracturing; drilling and operating risks; the adequacy of our
capital resources and liquidity; risks related to the concentration of
our operations in the Permian Basin; the results of our hedging program;
weather; litigation; shortages of oilfield equipment, services and
qualified personnel and increases in costs for such equipment, services
and personnel; uncertainties about our ability to replace reserves and
economically develop our current reserves; competition in the oil and
natural gas industry; and other important factors that could cause
actual results to differ materially from those projected.

We may use the terms “unproved reserves,” “resource potential,” “EUR”
per well and “upside potential” to describe estimates of potentially
recoverable hydrocarbons that the U.S. Securities and Exchange
Commission (“SEC”) rules prohibit from being included in filings with
the SEC. These are based on analogy to the Company’s existing models
applied to additional acres, additional zones and tighter spacing and
are the Company’s internal estimates of hydrocarbon quantities that may
be potentially discovered through exploratory drilling or recovered with
additional drilling or recovery techniques. These quantities may not
constitute “reserves” within the meaning of the Society of Petroleum
Engineer’s Petroleum Resource Management System or SEC rules. EUR
estimates, resource potential and drilling locations have not been fully
risked by Company management and are inherently more speculative than
proved reserves estimates. Actual locations drilled and quantities that
may be ultimately recovered from the Company’s interests could differ
substantially. There is no commitment by the Company to drill all of the
drilling locations which have been attributed to these quantities.
Factors affecting ultimate recovery include the scope of our ongoing
drilling program, which will be directly affected by the availability of
capital, drilling and production costs, availability of drilling
services and equipment, drilling results, lease expirations,
transportation constraints, regulatory approvals and other factors; and
actual drilling results, including geological and mechanical factors
affecting recovery rates. Estimates of unproved reserves, resource
potential, per well EUR and upside potential may change significantly as
development of the Company’s oil and natural gas assets provide
additional data. Our production forecasts and expectations for future
periods are dependent upon many assumptions, including estimates of
production decline rates from existing wells and the undertaking and
outcome of future drilling activity, which may be affected by
significant commodity price declines or drilling cost increases.

Any forward-looking statement speaks only as of the date on which
such statement is made, and the Company undertakes no obligation to
correct or update any forward-looking statement, whether as a result of
new information, future events or otherwise, except as required by
applicable law.

Treasury stock, at cost; 127,305 and 86,861 shares at December 31,
2013 and 2012, respectively

(10,884

)

(7,186

)

Total stockholders’ equity

3,757,949

3,466,196

Total liabilities and stockholders’ equity

$

9,591,164

$

8,589,437

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands, except per share amounts)

2013

2012

2013

2012

Operating revenues:

Oil sales

$

525,546

$

383,494

$

1,938,433

$

1,482,998

Natural gas sales

106,540

94,032

381,486

336,816

Total operating revenues

632,086

477,526

2,319,919

1,819,814

Operating costs and expenses:

Oil and natural gas production

127,141

92,102

455,436

343,743

Exploration and abandonments

71,752

12,505

109,549

39,840

Depreciation, depletion and amortization

214,833

166,453

772,608

575,128

Accretion of discount on asset retirement obligations

1,637

1,361

6,047

4,187

Impairments of long-lived assets

-

-

65,375

-

General and administrative (including non-cash stock-based
compensation of

$9,800 and $8,438 for the three months ended December 31, 2013 and

2012, respectively, and $35,078 and $29,872 for the years ended

December 31, 2013 and 2012, respectively)

44,695

37,802

169,815

133,796

(Gain) loss on derivatives not designated as hedges

(33,651

)

(17,901

)

123,652

(127,443

)

Total operating costs and expenses

426,407

292,322

1,702,482

969,251

Income from operations

205,679

185,204

617,437

850,563

Other income (expense):

Interest expense

(56,401

)

(53,632

)

(218,581

)

(182,705

)

Loss on extinguishment of debt

-

-

(28,616

)

-

Other, net

(11,275

)

(3,670

)

(13,081

)

(8,587

)

Total other expense

(67,676

)

(57,302

)

(260,278

)

(191,292

)

Income from continuing operations before income taxes

138,003

127,902

357,159

659,271

Income tax expense

(32,214

)

(46,714

)

(118,237

)

(251,041

)

Income from continuing operations

105,789

81,188

238,922

408,230

Income (loss) from discontinued operations, net of tax

-

(5,901

)

12,081

23,459

Net income

$

105,789

$

75,287

$

251,003

$

431,689

Basic earnings per share:

Income from continuing operations

$

1.01

$

0.78

$

2.28

$

3.96

Income (loss) from discontinued operations, net of tax

-

(0.05

)

0.11

0.22

Net income

$

1.01

$

0.73

$

2.39

$

4.18

Diluted earnings per share:

Income from continuing operations

$

1.01

$

0.78

$

2.28

$

3.93

Income (loss) from discontinued operations, net of tax

-

(0.06

)

0.11

0.22

Net income

$

1.01

$

0.72

$

2.39

$

4.15

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

Years Ended December 31,

(in thousands)

2013

2012

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income

$

251,003

$

431,689

Adjustments to reconcile net income to net cash provided by
operating activities:

Depreciation, depletion and amortization

772,608

575,128

Accretion of discount on asset retirement obligations

6,047

4,187

Impairments of long-lived assets

65,375

-

Exploration and abandonments, including dry holes

80,714

19,913

Non-cash compensation expense

35,078

29,872

Deferred income taxes

102,427

241,819

Loss on disposition of assets, net

1,268

372

(Gain) loss on derivatives not designated as hedges

123,652

(127,443

)

Discontinued operations

(12,250

)

49,011

Other non-cash items

19,720

12,420

Changes in operating assets and liabilities, net of acquisitions and
dispositions:

Accounts receivable

(40,009

)

(23,091

)

Prepaid costs and other

4,945

(8,200

)

Inventory

509

(1,587

)

Accounts payable

(18,469

)

4,165

Revenue payable

28,593

16,012

Other current liabilities

(59,191

)

13,211

Net cash provided by operating activities

1,362,020

1,237,478

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures on oil and natural gas properties

(1,850,992

)

(2,717,283

)

Additions to other property and equipment

(28,678

)

(56,588

)

Proceeds from the disposition of assets

15,217

492,497

Funds held in escrow

-

17,394

Settlements received from (paid on) derivatives not designated as
hedges

(32,341

)

23,536

Net cash used in investing activities

(1,896,794

)

(2,240,444

)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from issuance of debt

3,257,575

4,262,000

Payments of debt

(2,729,700

)

(3,241,500

)

Exercise of stock options

3,223

8,123

Excess tax benefit from stock-based compensation

6,147

18,963

Payments for loan costs

(14,075

)

(23,926

)

Purchase of treasury stock

(3,698

)

(3,190

)

Bank overdrafts

12,443

(14,966

)

Net cash provided by financing activities

531,915

1,005,504

Net increase (decrease) in cash and cash equivalents

(2,859

)

2,538

Cash and cash equivalents at beginning of period

2,880

342

Cash and cash equivalents at end of period

$

21

$

2,880

SUPPLEMENTAL CASH FLOWS:

Cash paid for interest and fees

$

200,961

$

158,715

Cash paid for income taxes

$

21,376

$

19,674

Concho Resources Inc.Summary Production and Price DataUnaudited

The following table sets forth summary information from our continuing
and discontinued operations concerning our production and operating data
for the periods indicated:

Three Months Ended

Years Ended

December 31,

December 31,

2013

2012

2013

2012

Production and operating data from continuing and discontinued
operations:

Net production volumes:

Oil (MBbl)

5,750

4,950

21,126

18,003

Natural gas (MMcf)

19,048

19,621

75,054

70,591

Total (MBoe)

8,925

8,220

33,635

29,768

Average daily production volumes:

Oil (Bbl)

62,500

53,804

57,879

49,189

Natural gas (Mcf)

207,043

213,272

205,627

192,872

Total (Boe)

97,007

89,350

92,150

81,334

Average prices:

Oil, without derivatives (Bbl)

$

91.40

$

81.28

$

91.76

$

88.01

Oil, with derivatives (Bbl) (a)

$

91.56

$

87.50

$

89.79

$

89.25

Natural gas, without derivatives (Mcf)

$

5.59

$

5.06

$

5.08

$

5.03

Natural gas, with derivatives (Mcf) (a)

$

5.83

$

5.07

$

5.21

$

5.05

Total, without derivatives (Boe)

$

70.82

$

61.02

$

68.97

$

65.16

Total, with derivatives (Boe) (a)

$

71.42

$

64.80

$

68.01

$

65.95

Operating costs and expenses per Boe:

Lease operating expenses and workover costs

$

8.57

$

7.17

$

7.85

$

7.27

Oil and natural gas taxes

$

5.68

$

5.19

$

5.69

$

5.43

Depreciation, depletion and amortization

$

24.07

$

20.73

$

22.97

$

20.34

General and administrative

$

5.01

$

4.51

$

5.04

$

4.40

(a)

Includes the effect of cash settlements received from (paid on)
commodity derivatives not designated as hedges:

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands)

2013

2012

2013

2012

Cash receipts from (payments on) derivatives not designated as
hedges:

Oil derivatives

$

912

$

30,785

$

(41,616

)

$

22,411

Natural gas derivatives

4,431

236

9,275

1,125

Total

$

5,343

$

31,021

$

(32,341

)

$

23,536

The presentation of average prices with derivatives is a non-GAAP
measure as a result of including the cash receipts from (payments
on) commodity derivatives that are presented in our statements of
cash flows. This presentation of average prices with derivatives is
a means by which to reflect the actual cash performance of our
commodity derivatives for the respective periods and presents oil
and natural gas prices with derivatives in a manner consistent with
the presentation generally used by the investment community.

The following table sets forth summary information from our continuing
operations concerning production and operating data for the periods
indicated:

Three Months Ended

Years Ended

December 31,

December 31,

2013

2012

2013

2012

Production and operating data from continuing operations:

Net production volumes:

Oil (MBbl)

5,750

4,718

21,126

16,859

Natural gas (MMcf)

19,048

18,462

75,054

66,613

Total (MBoe)

8,925

7,795

33,635

27,961

Average daily production volumes:

Oil (Bbl)

62,500

51,283

57,879

46,063

Natural gas (Mcf)

207,043

200,674

205,627

182,003

Total (Boe)

97,007

84,728

92,150

76,397

Average prices:

Oil, without derivatives (Bbl)

$

91.40

$

81.28

$

91.76

$

87.96

Oil, with derivatives (Bbl) (a)

$

91.56

$

87.81

$

89.79

$

89.29

Natural gas, without derivatives (Mcf)

$

5.59

$

5.09

$

5.08

$

5.06

Natural gas, with derivatives (Mcf) (a)

$

5.83

$

5.11

$

5.21

$

5.07

Total, without derivatives (Boe)

$

70.82

$

61.26

$

68.97

$

65.08

Total, with derivatives (Boe) (a)

$

71.42

$

65.24

$

68.01

$

65.93

Operating costs and expenses per Boe:

Lease operating expenses and workover costs

$

8.57

$

6.64

$

7.85

$

6.90

Oil and natural gas taxes

$

5.68

$

5.17

$

5.69

$

5.39

Depreciation, depletion and amortization

$

24.07

$

21.35

$

22.97

$

20.56

General and administrative

$

5.01

$

4.85

$

5.04

$

4.79

(a)

Includes the effect of cash settlements received from (paid on)
commodity derivatives not designated as hedges:

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands)

2013

2012

2013

2012

Cash receipts from (payments on) derivatives not designated as
hedges:

Oil derivatives

$

912

$

30,785

$

(41,616

)

$

22,411

Natural gas derivatives

4,431

236

9,275

1,125

Total

$

5,343

$

31,021

$

(32,341

)

$

23,536

The presentation of average prices with derivatives is a non-GAAP
measure as a result of including the cash receipts from (payments
on) commodity derivatives that are presented in our statements of
cash flows. This presentation of average prices with derivatives is
a means by which to reflect the actual cash performance of our
commodity derivatives for the respective periods and presents oil
and natural gas prices with derivatives in a manner consistent with
the presentation generally used by the investment community.

The following tables provide information that the Company believes may
be useful to investors who follow the practice of some industry analysts
who adjust reported company net income and cash flows from operating
activities to exclude certain non-cash and unusual items.

Adjusted Net Income

The following table provides a reconciliation of net income (GAAP) to
adjusted net income (non-GAAP) for the periods indicated:

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands, except per share amounts)

2013

2012

2013

2012

Net income - as reported

$

105,789

$

75,287

$

251,003

$

431,689

Adjustments for certain non-cash and unusual items:

(Gain) loss on derivatives not designated as hedges

(33,651

)

(17,901

)

123,652

(127,443

)

Cash receipts from (payments on) derivatives not designated as hedges

5,343

31,021

(32,341

)

23,536

Impairments of long-lived assets

-

-

65,375

-

Leasehold abandonments

35,930

3,161

49,758

12,395

Loss on extinguishment of debt

-

-

28,616

-

(Gain) loss on disposition of assets, net

(449

)

87

1,268

372

Other

11,393

3,242

11,393

3,242

Discontinued operations:

(Gain) loss on disposition of assets

-

18,704

(19,599

)

18,704

Tax impact (a)

(7,204

)

(13,985

)

(88,511

)

26,363

Change in state statutory effective income tax rate

(21,876

)

-

(21,876

)

-

Adjusted net income

$

95,275

$

99,616

$

368,738

$

388,858

Adjusted earnings per share:

Basic

$

0.91

$

0.96

$

3.52

$

3.77

Diluted

$

0.91

$

0.96

$

3.51

$

3.74

Effective tax rates

38.8

%

36.5

%

38.8

%

38.1

%

(a) The tax impact is computed utilizing the Company's adjusted
statutory effective federal and state income tax rates shown in the
table above.

Adjusted Cash Flows

The following table provides a reconciliation of cash flows from
operating activities (GAAP) to adjusted cash flows (non-GAAP) for the
periods indicated:

Years Ended December 31,

(in thousands)

2013

2012

Cash flows from operating activities

$

1,362,020

$

1,237,478

Settlements received from (paid on) derivatives not designated as
hedges (a)

(32,341

)

23,536

Adjusted cash flows

$

1,329,679

$

1,261,014

(a) Amounts are presented in cash flows from investing activities
for GAAP purposes.

EBITDAX

EBITDAX (as defined below) is presented herein, and reconciled from the
generally accepted accounting principles (“GAAP”) measure of net income
because of its wide acceptance by the investment community as a
financial indicator of a company's ability to internally fund
exploration and development activities.

The Company defines EBITDAX as net income, plus (1) exploration and
abandonments expense, (2) depreciation, depletion and amortization
expense, (3) accretion expense, (4) impairments of long-lived assets (5)
non-cash stock-based compensation expense, (6) (gain) loss on
derivatives not designated as hedges, (7) cash receipts from (payments
on) derivatives not designated as hedges, (8) (gain) loss on disposition
of assets, net, (9) interest expense, (10) loss on extinguishment of
debt, (11) federal and state income taxes on continuing operations and
(12) similar items listed above that are presented in discontinued
operations. EBITDAX is not a measure of net income or cash flows as
determined by GAAP.

The Company’s EBITDAX measure (which includes continuing and
discontinued operations) provides additional information which may be
used to better understand the Company’s operations. EBITDAX is one of
several metrics that the Company uses as a supplemental financial
measurement in the evaluation of its business and should not be
considered as an alternative to, or more meaningful than, net income, as
an indicator of operating performance. Certain items excluded from
EBITDAX are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and
tax structure, as well as the historic cost of depreciable assets, none
of which are components of EBITDAX. EBITDAX, as used by the Company, may
not be comparable to similarly titled measures reported by other
companies. The Company believes that EBITDAX is a widely followed
measure of operating performance and is one of many metrics used by the
Company’s management team, and by other users, of the Company’s
consolidated financial statements. For example, EBITDAX can be used to
assess the Company’s operating performance and return on capital in
comparison to other independent exploration and production companies
without regard to financial or capital structure, and to assess the
financial performance of the Company’s assets and the Company without
regard to capital structure or historical cost basis.

The following table provides a reconciliation of net income to EBITDAX
for the periods indicated:

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands)

2013

2012

2013

2012

Net income

$

105,789

$

75,287

$

251,003

$

431,689

Exploration and abandonments

71,752

12,505

109,549

39,840

Depreciation, depletion and amortization

214,833

166,453

772,608

575,128

Accretion of discount on asset retirement obligations

1,637

1,361

6,047

4,187

Impairments of long-lived assets

-

-

65,375

-

Non-cash stock-based compensation

9,800

8,438

35,078

29,872

(Gain) loss on derivatives not designated as hedges

(33,651

)

(17,901

)

123,652

(127,443

)

Cash receipts from (payments on) derivatives not designated as hedges

5,343

31,021

(32,341

)

23,536

(Gain) loss on disposition of assets, net

(449

)

87

1,268

372

Interest expense

56,401

53,632

218,581

182,705

Loss on extinguishment of debt

-

-

28,616

-

Income tax expense from continuing operations

32,214

46,714

118,237

251,041

Discontinued operations

-

21,299

(12,081

)

64,701

EBITDAX

$

463,669

$

398,896

$

1,685,592

$

1,475,628

Concho Resources Inc.

Costs Incurred

Unaudited

The table below provides the costs incurred for the periods
indicated:

Costs incurred for oil and natural gas producing activities (a)

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands)

2013

2012

2013

2012

Property acquisition costs:

Proved

$

9,123

$

2,063

$

11,499

$

857,836

Unproved

26,706

29,932

85,538

441,042

Exploration

250,767

214,109

1,029,793

781,174

Development

145,424

166,665

738,430

741,206

Total costs incurred for oil and natural gas properties

$

432,020

$

412,769

$

1,865,260

$

2,821,258

(a)

The costs incurred for oil and natural gas producing activities
includes the following amounts of asset retirement obligations:

Three Months Ended

Years Ended

December 31,

December 31,

(in thousands)

2013

2012

2013

2012

Exploration costs

$

583

$

159

$

2,672

$

2,611

Development costs

304

7,234

9,467

15,536

Total asset retirement obligations

$

887

$

7,393

$

12,139

$

18,147

Concho Resources Inc.

Derivatives Information

Unaudited

The tables below provide data associated with the Company’s
derivatives at February 19, 2014 for the periods indicated:

2014

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Total

Oil Swaps: (a)

Volume (Bbl)

5,075,000

4,544,000

4,116,000

3,833,000

17,568,000

Price (Bbl)

$

93.65

$

92.69

$

91.23

$

91.09

$

92.27

Oil Basis Swaps: (b)

Volume (Bbl)

2,790,000

3,458,000

3,956,000

3,680,000

13,884,000

Price (Bbl)

$

(0.46

)

$

(0.72

)

$

(0.99

)

$

(0.92

)

$

(0.80

)

Natural Gas Swaps: (c)

Volume (MMBtu)

3,812,000

3,001,000

2,300,000

1,777,000

10,890,000

Price (MMBtu)

$

4.19

$

4.18

$

4.19

$

4.19

$

4.19

Natural Gas Collars: (d)

Volume (MMBtu)

5,400,000

5,460,000

5,520,000

5,520,000

21,900,000

Ceiling Price (MMBtu)

$

4.40

$

4.40

$

4.40

$

4.40

$

4.40

Floor Price (MMBtu)

$

3.85

$

3.85

$

3.85

$

3.85

$

3.85

2015

2016

2017

Oil Swaps: (a)

Volume (Bbl)

12,812,000

429,000

168,000

Price (Bbl)

$

86.86

$

88.31

$

87.00

Natural Gas Swaps: (c)

Volume (MMBtu)

20,075,000

-

-

Price (MMBtu)

$

4.15

$

-

$

-

(a)

The index prices for the oil contracts are based on the NYMEX – West
Texas Intermediate (“WTI”) monthly average futures price.

(b)

The basis differential price is between the Midland – WTI and the
Cushing – WTI.

(c)

The index prices for the natural gas price swaps are based on the
NYMEX – Henry Hub last trading day futures price.

(d)

The index prices for the natural gas collars are based on the El
Paso Permian delivery point.